There is a glut of natural gas. Everybody knows that. There’s so much of the latest multi stage hydraulic fracturing going on from New York State to Texas and all places in between, prices will be low forever. But just as a full watering hole can deplete quickly the current gas storage glut can recede. In fact it already has been and at an alarmingly brisk pace and there may be a confluence of other events which could hasten the process. Consider this. The weekly EIA natural gas storage numbers reported each Thursday came in with a 28 billion cubic feet (bcf) injection. The inventory increase last year at this time was 67 bcf while the five year average accretion was 74 bcf. So true that one week does not a trend make. But this makes eleven straight weeks that have experienced below average storage injections. After Thursday’s numbers were released inventories stood at 3.163 Trillion Cubic Feet or 19.2% above last year but only 17.5% above the five year average. A seemingly decent cushion until you consider as recently as May 10 stockpiles were 48.4% and 49.9% ahead of the previous year and the five year averages respectively. So the question becomes, why are rates of gas injection dropping so precipitously unless the shale plays are actually unable to produce the necessary incremental volumes.

A Little History And Some Facts

Natural Gas production in the US was declining steadily until 2005 into what many perceived as an irreversible trend with an implication of persistent shortages. Enter the knight in shining armor; horizontal resource drilling. Daily gas production increased from 51 bcfd in 2005 to an average of 66.2 bcfd (billion cubic feet per day) in 2011. Some months have even spiked above 70 bcfd. The natural gas rig count peaked at 1,600 in the summer of 2008. No coincidence gas prices topped out concurrently the first few days in July at $13.28 per mcf. So in six plus years while gas drillers were able to increase daily supply by 30% demand has increased only half that amount. The result has been a spot gas price that bottomed on April 17, 2012 at $1.89 per mcf (thousand cubic feet). But the pendulum is now trending in the other direction as power suppliers and the transportation industry begin to capitalize on the low price of natural gas.

The EIA (US Energy Information Association) has prognosticated a 2012 daily production average of 68.98 bcfd and consumption of 69.91 bcfd. Methinks those production numbers extravagantly optimistic and yet the agency continues to publicly adhere to them. Firstly, actual output over the last two months has already slipped to a bit under 64 bcfd. Next, the natural gas rig count collapsed to 486, a thirteen year low, on June 22 and had made only minimal recovery to 518 rigs as of last week. Lastly, numerous major gas producers such as COP and CHK have shut in parts of their dry gas production and are switching their drilling programs away from dry gas to natural gas liquids and oil. Conversely, consumption may exceed EIA projections. Here’s why. Hotter than usual temperatures across much of the country especially in the population heavy northeast is causing excess energy demand. Another thought provoking data point from the EIA last week reported that for the first time in history natural gas fired power plants generated more electricity than coal fired plants. That’s quite a milestone. Each now comprise 32% of U.S. power generation. Gas is cleaner and at current prices is a cost effective coal alternative. Adding to short term supply pressures, four nuclear power plants are down, all effecting east coast residents. Though still in early stages numerous fortune 500 companies such as Fed Ex and UPS are transitioning to natural gas powered trucks. A national fueling system is near completion with locations along the major interstate arteries.

Drilling Economics

The earliest horizontal resource drilling was done by Mitchell Energy (now part of DVN) in 2005 in the Barnett Shale which is in and around Fort Worth, Texas. Horizontal fracturing into shale has become much more sophisticated since those early days, with enhanced recovery of gas in place, although at much greater cost per well. An average 20 stage horizontal dry gas well in the South Texas Eagle Ford Shale or the East Texas/North Louisiana Haynesville play may cost $8.5 to $12 million. It will be drilled to vertical depths of 8,000 to 12,000 feet below surface. I have examined production data for over 50 wells that have been operating for 9 months to over a year and a half. Now let’s do some arithmetic. Let’s assume an average well cost of $10 million with an estimated ultimate recovery (EUR) of 6 bcf. At $2.00 per mcf gross expected revenues are $12 million and at $3.00 mcf revenues are $18 million and so on. Don’t forget about the expense side of the ledger. There is the mineral owner royalty payment which is often ¼ or 25% which comes right off the top. There are state severance taxes which vary from state to state but in Texas are 7.5%. There are ad valorem taxes of about 2% as well. Operating expenses will average $120,000 to $160,000 per well per year. Then the gas must be “cleaned” to make it conform to pipeline specifications. The highly toxic H2S (hydrogen sulfide) and CO2 (carbon dioxide) are removed along with excess water to get the gas below 7 ppm (parts per million). Only then is it ready to go into a KMP or EPD main high pressure sales pipeline. Estimated price tag for this gas prep is at least $.25 per mcf. Then after some number of years the well pressure will fall below certain levels and a compressor will need to be installed. If gas prices are low (like now) and the well’s gas production has declined to a small fraction of its original flow rates, the calculation is made as to which is more economic; install the compressor or shut in the production all together. The latter is the decision reached by hundreds of producers across the country. You are welcome to check my calculations but you lose a whole lot of money at $2.00 gas, lose some money at $3.00 gas, and make less than a 5% return at $4.00 gas. And all this assumes you can make an average of 6 bcf per well. The debate on this issue is becoming quite spirited. Recent data now suggest that many of these deep multistage horizontal wells are declining at greater than anticipated rates of 80% to as much as 90% in the first year. This was the case for almost all the well data that I inspected. So this means if production began at 5mmcf (million cubic feet) per day that by the end of year one that number may be reduced to 500 mcf to 750 mcf per day. The equally consequential part of this dispute is how long does this production last. The certain answer is that nobody knows for sure. The technology is so new that there aren’t any deep (below 10,000 feet) multistage horizontals that have been on production for 10 years or even 5 years. But if, and it is if, the “tail” in these shale wells fizzles out and the well becomes uneconomic after 8 or even 12 years instead of the projected 25 year life then the entire economics of the shale boom must be revisited.